Method and apparatus for real time enhancing of the operation of a fluid transport pipeline

ABSTRACT

A real time method and dynamic logic-based system for enhancing the operation of a pipeline network is disclosed. The system and method perform monitoring of the operation of a pipeline network, generate alarms in response to differing levels of destabilized pipeline operations, manage the generation of alarms based upon known operating events and operating conditions, diagnose potential source of the detected destabilized events and manage the operation of the pipeline.

CROSS REFERENCE TO RELATED PATENT APPLICATION

This application relates and claims priority to U.S. Provisional PatentApplication No. 61/129,466, filed on Jun. 27, 2008, entitled “A Methodand Apparatus for Enhancing the Operation of a Fluid TransportPipeline.”

FIELD OF THE INVENTION

The present invention relates to a method and system for enhancing theoperation of a pipeline. In particular, the present invention isdirected to a real time method and a dynamic, logic-based system formonitoring the operation of a pipeline network, generating alarms inresponse to differing levels of destabilized pipeline operations andmanaging the operation of the pipeline in response to the same. Inparticular, the present invention relates to a method and a dynamicbehavior based system for the monitoring of a pipeline, and thedetection and reporting of destabilized operating events including butnot limited to possible pipeline rupture events based upon sensedhydraulic reactions within the pipeline network. The present inventionalso relates to a method and system for monitoring the generation ofalarms in response to sensed destabilizing events. The present inventionalso relates to a system for maintaining the stable operation of thepipeline, monitoring potential destabilizing events and pinpointing thelocation of the same in order to enact sufficient remedial measures toavoid or prevent a catastrophic destabilized event (e.g., leak, ruptureor equipment failure). The present invention also relates to a methodand system for diagnosing destabilizing events.

BACKGROUND OF THE INVENTION

Pipelines are used to efficiently transport fluid commodities from onelocation to another and, generally, span long distances. Pipelines aretypically monitored and controlled to ensure the integrity of thepipeline. This is normally accomplished from a central control centerwhere equipment settings and measured parameters are monitored andcontrolled. Leaks can be detected by measuring various parameters,particularly flow rate and pressure. This monitoring depends oncalculating the mass of the contents of the pipe (fluid), and observingover a period of time whether the contents of the pipe changes in amanner indicative of fluid leaving the pipe at an unmeasured location,perhaps through a rupture in the pipeline. The effect of a leak on themeasured parameters and thus on the calculated mass of fluid within thepipe is mathematically relatable to the mass of fluid which is leavingthe pipe through the rupture. Using existing methods, large ruptures canbe detected in relatively short periods of time. Small ruptures,however, if at all detectable, require longer periods of time toaccumulate the necessary volumetric discrepancies to indicate excessivesystem measurement imbalance, which may result in a greater amount offluid leaking from the system into the surrounding environment. Thesesystems depend on a balancing algorithm to determine if fluid is leavingthe pipeline at an un-metered location to determine if there is arupture. As may be appreciated, these prior art systems require that asufficient volume of fluid has left the pipeline through the rupturebefore detection of the rupture can occur. This can result in asignificant environmental impact in the area surrounding the rupture asinferential measurement systems are commonplace and relatively lethargicwith respect to hydraulic wavespeeds and the ensuing segmentaldecompressions that follow rupture events in closed pressurizedhydraulic networks.

Calculating the mass of the contents in the pipe is subject to manyinaccuracies (e.g., errors in measurement of the mass of the fluidentering and leaving the pipe, inaccurate knowledge of the changes inthe physical space within the pipe due to temperature fluctuations inthe pipeline walls and the minimal knowledge of the actual temperaturesand pressures within the pipeline, transducer calibration and/orconfiguration correctness).

The approximate location of a piping rupture can be determined usingexisting methods for large ruptures by examining the effects of therupture on the flow rate and pressure at locations where measurementsare available. Locating the rupture under existing methods is subject toseveral possible inaccuracies related to measurement system andancillary instrumentation system parameterization, configuration, andcalibration. As the volume of fluid exiting through the rupture drops toa small fraction of the flow rate of the pipeline, the effect of themissing fluid will drop below the accuracy with which the parametersused to calculate the location are measured. Additionally, commoninferential mass metering systems often operate within nonlinear regionsof equipment operation thus degrading leak detecting capabilities.

There is a need for a system and method to rapidly detect and accuratelypredict the location of a destabilizing event in a pipeline network.Others have attempted to develop systems that are more effective inidentifying ruptures than those described above, but these systems onlyidentify leaks and ruptures and not destabilizing events. Thesedestabilizing events may not be a leak or rupture, but impact theoperation of the pipeline. These systems, however, compare sensedconditions with pre-identified stored leak profiles. These systems donot identify unstable operations that are not leaks or ruptures, thelocations of these unstable operations or the source(s) of concern.These systems are not dynamic, as such, these systems do not adequatelyrespond to abnormal changes in the operation of a pipeline network thatare not indicative of the presence of a leak or a rupture.

U.S. Pat. No. 5,361,622 to Wall discloses a device and method for thedetection of leaks in a pipeline. Wall utilizes a transducer formeasuring instantaneous pipeline pressure. Wall utilizes a computer tocompare rates of change of the measured pressure at successivepreselected and fixed timed intervals at isolated nodes. The computercompares the measured rate of change with a preselected total change ina specified characteristic at that node. When the measured rate ofchange exceeds the preselected maximum total change, an alarm istriggered indicating the possibility of a leak or rupture. Thesemaximums, however, do not vary or adjust for variations in the pipelineoperation. Wall does not aid in the determining the location of the leakor rupture because its analysis is site specific. Wall provides forlocal or isolated analysis at select points within the pipeline. Walldoes not corroborate these changes with any changes occurring at othernodes. This lack of corroboration leads to a greater potential for falsealarms.

U.S. Pat. No. 5,388,445 to Walters et al discloses a method and anapparatus for detecting a wave front caused by the onset of leaks orother transient events in a pipeline. Walters seeks to detect asignificant wave front traveling in the high noise environmentcharacteristic of pipelines, and to accurately measure its amplitude andtime of arrival. Walters discloses detecting a wave front indicative ofa transient event occurring in a pipeline by measuring a characteristicrelated to pressure of a fluid in the pipeline with a measuring devicepositioned at a given point on the pipeline, and outputting analogsignals proportional to the pressure. The detection of the wave frontarrival time may be used directly to sound an alarm. The amplitude maybe used to find the location and/or size of the leak. Walters, however,does not provide means for discounting (i) external influences on thepipeline, which may produce wave fronts but are not leaks or (ii)internal influences such as changes in the viscosity or strip operationswithin the pipeline, which again may produce wave fronts but are notleaks. The model employed in Walters is a fixed model. It does notadjust or learn based upon varying pipeline operations and externalinfluences; rather, it relies upon a fixed reference event to determineleaks. Accordingly, the system disclosed by Walters may be prone tofalse leak indications. Furthermore, Walters looks at measurementsobtained during affixed time window and does not account for events thatmay start during one window and end during another window. Accordingly,the system may fail to detect a leak nor does it attempt to identify ordiagnose destabilizing events that are not leaks but that may adverselyaffect the pipeline network's efficiency of operation or safety.

U.S. Pat. No. 5,428,989 to Jerde et al discloses a method and anapparatus for detecting and characterizing a leak using a pressuretransient. Jerde provides a plurality of pressure monitoring stationsspaced along a pipeline at known distances from each other. The stationsgenerate an arrival time signal when a pressure wave front is detected.The system can determine whether the arrival time signals from theplurality of monitoring stations correspond to the same event.

U.S. Pat. No. 6,389,881 and U.S. Pat. No. 6,668,619 both to Yang et aldisclose an acoustic based method and apparatus for detecting andlocating leaks in a pipeline. Yang utilizes a system for detecting leaksusing the acoustic signal generated from a leak event in a pipeline. Thesystem requires the use of non-industry standard specialized componentsmounted to the pipeline at selected locations. A pattern match filter isused to reduce false alarm rate and improve leak location accuracy bycomparing acoustic waves generated by a leak with stored previouslyrecorded signature leak profiles. Yang utilizes a time stamp of theacoustic signal to pinpoint the location of the leak. The system listensfor acoustic waves to determine whether or not a leak is present. Normaloperating events (such as pump start ups, etc.) and isolated events(such as a piece of equipment hitting the pipeline) may generate anacoustic signal that travels through the pipeline but not a pressurewave characteristic of a leak. As such, the Yang system is more prone toissuing false alarms.

U.S. Pat. No. 6,970,808 to Abhulimen et al discloses a method fordetecting and locating leaks in a pipeline network in real-timeutilizing a flow model that characterizes flow behavior for at least oneof steady and unsteady states, which corresponding to an absence and apresence of model leaks in the pipeline network. A deterministic modelis provided to evaluate at least one of a leak status and a no leakstatus relating to the pipeline network using deterministic criteria.

These prior art systems are not proactive systems; rather, these systemsare reactive in nature relying upon comparisons to historical data orpredetermined modeled results in order to determine whether or not aleak is present. These prior art systems essentially reset to theoriginal threshold after each detection of a potential leak. Thethresholds of prior art do not rescale themselves in real time to takeinto account normal changes in pipeline operation. The thresholds aregenerally high, which overlook changes due to small leaks. These priorart systems do not rely upon present pipeline activity in order todetermine the presence of a leak or rupture, which may require furtheraction nor do they perform corroborating steps to confirm a destabilizedevent, nor do they diagnose the source of the destabilizing event (e.g.,process error, equipment malfunction). These systems do not continuouslyadjust detection thresholds to account for the various normal operatingmodes of pipeline networks. While it is desirable to maintain a stablepressure and stable flow through the pipeline network, changes inpressure and flow are common due to changes in viscosity of the variousfluids flowing through the network, equipment malfunction, etc. Theseprior art systems are not capable of accounting for these variations inpipeline activity. As such, these prior art systems may generate asignificant number of alarms indicating a potential leak. Each of thesealarms requires some form of action by a pipeline operator. There is aneed for a dynamic logic-based system that accurately responds to thevarying operating conditions present in a pipeline network whileaccurately identifying destabilizing events including leaks and ruptureswhile minimizing false alarm events. Furthermore, there is a need for asystem that effectively manages the generation of alarms.

SUMMARY OF THE INVENTION

It is an aspect of the present invention to provide a method and dynamicsystem of monitoring a pipeline network to identify possibledestabilizing events in the pipeline network. The present invention isintended for use in various pipeline networks and is not intended to belimited to those networks used for transporting oil, liquefied naturalgas, gas or products derived from the same. The method and associatedsystem are contemplated for use in pipeline networks including but notlimited to networks interconnecting one or more of the following:refineries, petrochemical production facilities, pumping stations,storage facilities, distribution terminals, drilling stations, off-shoreterminals and off-shore drilling platforms. It is contemplated thepresent invention has application in any environment where a liquid orother fluid is transported via pipeline (e.g., water distributionsystem, food processing facilities, etc).

The method according to an aspect of the present invention may includesensing one or more pressure waves within the pipeline network atpredetermined locations within the pipeline network, and determining thepresence of a possible destabilizing event in the pipeline network inresponse to the sensed pressure waves. The destabilizing events can varyfrom a leak or rupture of the pipeline to a component failure in thefield (e.g., a pump or valve or other pipeline equipment related to theoperation of the pipeline) to a process error, which may attributed toan operator error (e.g., set point misplacement of a control valve orvariable frequency drive adjustment) or misoperation of the pipeline.The destabilized events have varying degree of severity (with apotential leak or rupture having the highest level of severity).Nonetheless, each destabilizing event requires some level of attention.If a low level destabilizing event continues without implementingremedial measures steps, the efficient operation of the pipeline may beimpacted, resulting in a potential fail safe operation (e.g.,insufficient fluid feed to a pipeline pump, pressure within the pipelineis too high, component failure, etc.) By implementing correctivemeasures to stabilize the destabilizing event, potential ruptures andleaks can be prevented, stable operation is maintained, efficientpipeline operation is returned, damage to equipment is prevented andpipeline life may be extended (through reductions in strain, fatigue andwear on the pipeline).

In accordance with an aspect of the present invention, the sensing ofpressure waves within the pipeline network occurs at the highestsampling rate permitted or sample rate limit of the pressure transmittersensor associated with the pipeline. The sampling is accomplished usingexisting pipeline equipment and does not require the placement ofadditional or customized equipment on the pipeline for purposes of eventdetection. The sampling is repeated in order to determine the presenceof a destabilizing event in the pipeline network. Determining thepresence of a possible destabilizing event in the pipeline network inresponse to the sensing of the pressure waves may include detectingvariations in the sensed pressure waves. This may include the use of theSCADA system to determine whether rapid pressure decay and thesubsequental segmental decompression characteristic of leak events on apressurized hydraulic network occured within the pipeline system. Themethod preferably includes determining whether or not the detectedvariation exceeds an accepted standard deviation. Unlike prior artsystems, the use as applied within the present invention of the standarddeviation takes into account varying modes of pipeline operation (e.g.,draw mode, where pipeline fluid is pushed from one end to the other butis also withdrawn at intermediate points, and tight line mode, where nopipeline fluid is withdrawn at intermediate points, etc.). The prior artsystems rely upon a fixed threshold. When the threshold is exceeded, analarm is triggered. According to an aspect of the present invention, thethreshold utilized changes to account for changes in the operatingconditions due to changes in operating mode, changes in operation due tonormal noise, temperature, different types of fluids (e.g., gasoline ordiesel fuels) and location of the pipeline (e.g., above ground, belowground, underwater). The threshold may be increased or decreased inresponse to known operating conditions or events. For example, thethreshold may be increased in response to the startup or shutdown of apump or other pipeline equipment. Increasing the threshold prevents theidentification of an operationally acceptable destabilizing event thatmay be solely attributable to the component startup. When a pump shutsdown, and steadystate is reattained, the threshold may be decreased orretuned from transient noise to steadystate normal noise thereby moretightly monitoring the system for operationally unacceptabledestabilizing events. This would allow the detection of destabilizingevents that may not have been identified if the threshold was maintainedconstant. Using the standard deviation, the reported high speed pressuredecay can be analyzed to determine if it originated from known pipelineoperational activities or is attributable to a potential leak or otherdestabilizing event. The presence of a high speed pressure decay isindicative of a leak or rupture. In the event that the pipeline issubmerged underwater, there may be an increase in pressure as opposed toa pressure decay due to the pressure exerted on the pipeline from thewater entering the pipeline. A comparison of the time of reportedpressure reactions with the times of recent pipeline operationalactivities is made to determine if given the time differential andlinear pipeline distance between the activity and the detection of thepressure response was caused by the normal pipeline activity bycomparing time, speed, and distance calculations against known pipelineparameters and fluid wave propagating characteristics. The sensedpressure pulse for a destabilizing event moves faster through thepipeline than the normal flow profile of the fluid within the network.

In accordance with another aspect of the present invention, the methodof monitoring the pipeline network may further comprise determining thelocation of the possible destabilizing event in the pipeline network inresponse to the sensed pressure waves. The presence and location of thepossible destabilizing event may be reported to one or more operators ofthe pipeline network. In the event the destabilizing event is of a highlevel, the operator takes appropriate remedial measures (e.g., pumpshutdown, setpoint adjustment, valve operation, system shutdown) tominimize the loss of fluid from the system and minimize the impact tothe surrounding environment. Determining the location of a possibledestabilizing event in the pipeline network in response to the sensedpressure waves may include identifying which predetermined locations adestabilizing event (e.g., a rupture) indicating pressure reaction issensed at a first sensing time, then identifying which predeterminedlocations the sensed pressure wave is sensed at a second sensing time,and determining the location of a possible destabilizing event basedupon the location of the sensed pressure wave at the first sensing timeand the second sensing time. The plurality of coincidentally timedpressure reactions are analyzed to determine a probable location of theincident which caused the pressure reaction. The sensed reactions'chronology is compared for reasonableness against known parameters ofthe subject pipeline system and the fluid or fluid set within thepipeline.

In accordance with another aspect of the present invention, the methodof monitoring a pipeline network may further include determining thecertainty of the possible destabilizing event and reporting thepresence, location and certainty of the possible destabilizing event toone or more operators of the pipeline network. The certainty of thepossible destabilizing event may include comparing the determination ofa possible destabilizing event based upon sensed pressure waves with oneor more current sensed pipeline network operating conditions.

It is another aspect of the present invention to provide a system formonitoring a pipeline network for detecting destabilizing events in thesame. The pipeline network may include a first facility, a secondfacility, at least one pipeline segment connecting the first facilityand the second facility such that the fluid can flow between the firstfacility and the second facility, and at least one pumping station(which may include a pump set) connected to the at least one pipelinesegment. Various facilities are contemplated to be within the scope ofthe present invention including but not limited to refineries,petrochemical production facilities, pumping stations, storagefacilities, distribution terminals, drilling stations, and off-shoredrilling platforms. For example, the pipeline may extend from a refineryto a distribution terminal, an off-shore drilling platform or terminalto on-shore storage or processing facilities or refinery. The network isnot limited to two facilities. Various combinations and numbers offacilities and pipeline segments are considered to be within the scopeof the present invention. Each pumping station preferably includes atleast one pump. The pumping stations may include a centrifugal type pumpor pump set for withdrawing fluid at the desired pressure and rate fromthe upstream pipeline segment and pushing the fluid into the downstreampipeline segment at the desired pressure and rate. The monitoring systemincludes a plurality of pressure sensing devices for sensing thepresence of one or more pressure waves within the pipeline network. Eachpressure sensor device is preferably an existing pressure transmitterassociated with the pipeline. The plurality of pressure sensing devicespreferably includes a pair of pressure sensing devices for each pumpingstation. A first sensing device of the pair of pressure sensing devicesis located on one side of the pump or pump set and a second sensingdevice of the pair of pressure sensing devices is located on an oppositeside of the pump or pump set. Each pressure sensing device is capable ofsensing one or more pressure waves within the pipeline network. Themonitoring system further includes a plurality of remote monitoringdevices operatively connected to the first facility, the second facilityand at least one pumping station. The remote monitoring devices monitorthe operation of the pipeline network and collect operating data of thepipeline network from the sensing devices and other monitoring devices.Each of the plurality of pressure sensing devices is operativelyconnected to at least one remote monitoring device. The monitoringsystem further includes a control unit operatively connected to theplurality of remote monitoring devices for controlling the operation ofthe pipeline network based upon signals received from the plurality ofremote monitoring devices. The control unit detects the presence ofpossible destabilizing events in the pipeline network and determines thelocation of possible destabilizing events in the pipeline network basedupon the sensed pressure waves. This application is performed by a highspeed time-synchronized array of pressure sensing field locatedinstruments and processors.

The control unit includes a real time optimizer. The real time optimizerdetermines the presence of a destabilizing event in the pipeline networkbased upon the sensed pressure waves. Furthermore, the real timeoptimizer determines whether or not variations in the sensed pressurewaves are present and whether or not each variation or variation setexceeds an accepted standard deviation (with respect to empiricallydetermined normal pipeline system behavior for the current mode) orother statistical comparator (e.g., positive or negative rate of changeof decompression in the network). The real time optimizer may furthercorroborate and determine the certainty of the possible destabilizingevent by comparing the determination of a possible destabilizing eventbased upon sensed pressure waves with one or more sensed pipelinenetwork operating conditions sensed by the plurality of remotemonitoring devices. The real time optimizer determines the location ofthe destabilizing event in the pipeline network based upon the locationof the pressure sensing devices that sensed a pressure wave of aparticular reaction and the actual real-time pipeline system hydrauliccharacter with respect to the empirically determined acceptablehydraulic profile.

The control unit may identify remedial measures to address thedestabilizing event including but not limited to the modification ofoperating parameters, the resetting of equipment, notifying the humanpipeline controller, and/or the maintenance review of equipment inresponse to the determination that a destabilization event exists. Inthe event that a rupture or leak is detected the control unit mayidentify or automatically execute remedial measures to minimize fluidloss from the system. The remedial measures may include but are notlimited to the powering off of pumps to reduce flow to the leak,temporarily shutting down the pipeline, diverting the flow within thepipeline, and isolating the leak site.

It is another aspect of the present invention to provide a system thateffectively provides for alarm management to reduce the number of thefalse alarms. During normal operation of the pipeline network, varioussteady-state and transient pressure profiles are generated that are notattributable to a destabilizing event, but nonetheless create pressureactivity that generates an alarm signal. These can be attributed tonormal pipeline operation and can be indicative of changes in operatingmode and/or changes in operating events. For example, changing theoperating mode from tight line mode to draw mode may create a pressurewave within the network giving rise to an alarm. Similarly, the normaloperation of pumping units within the network (i.e., turning pumps on,off or adjusting a variable frequency drive) may create a pressure wavewithin the network giving rise to an alarm. These pressure waves reflectnormal pipeline operation but may give rise to hundreds of false alarmson a daily basis. The dynamic nature of the system in accordance withthe present invention provides effective alarm management to reduce theoverall occurrence of the false alarms. This reduction in false alarmsprovides the pipeline operator with more time to address and respond toactual alarms as well as heighten the operator's sensitivity to actualalarms.

In accordance with another aspect of the present invention, a method andsystem for managing the generation of alarms for possible destabilizingevents in a pipeline network is provided. The system preferably performsthe method described herein. The method includes sensing one or morepressure waves within the pipeline network at predetermined locationswithin the pipeline network, automatically adjusting a predeterminedstable operating threshold for the pipeline network at the predeterminedlocations based upon at least one of the operating mode of the pipelinenetwork, current operating conditions in the pipeline network andcurrent operating events in the pipeline network, and determining thepresence of a possible destabilizing event in the pipeline network bydetermining whether or not the sensed pressure waves exceed the adjustedpredetermined stable operating threshold. In response to thedetermination, the method further includes generating an alarmindicating the possible presence of a destabilizing event when thesensed pressure waves exceed the adjusted predetermined stable operatingthreshold. The determination of the presence of a possible destabilizingevent in the pipeline network in response to the sensed pressure wavesmay further include detecting variations in the sensed pressure waves,and determining whether or not the detected variation exceeds anaccepted standard deviation. The accepted standard deviation may be anempirically determined standard deviation. The method may furtherinclude determining whether or not a subsequential decompressioncharacteristic is present following the detection of a variation insensed pressure waves. When the characteristic is present, an alarm isgenerated indicating the presence of a leak.

It is another aspect of the present invention to provide a monitoringsystem for detecting destabilizing events in a pipeline network anddiagnosing the destabilizing events to identify (i) the location of thesame and (ii) identify potential causes and remedial and/or correctivemeasures for the same. The system is especially useful in diagnosingboth high level and lower level destabilizing events such thatcorrective measures can be implemented to minimize any long termdetrimental impact on the pipeline network and to promptly return thenetwork to stable operation.

In accordance with another aspect of the present invention, the apipeline monitoring system is provided that diagnoses the potentialsource of destabilizing events. The system includes a control unit thatdiagnoses a potential cause of the sensed destabilizing event bycomparing the character of the sensed destabilizing event using anexpert based diagnostic subroutine with at least one of priordestabilizing events, the current operating mode of the pipelinenetwork, the current operating conditions in the pipeline network andthe current operating events in the pipeline network. The control unitmay identify remedial measures to isolate or correct the possibledestabilizing event in response to the determination that a possibledestabilizing event exists. The control unit may then report theremedial measures to an operator of the pipeline network. It is alsocontemplated that the control unit may automatically execute theremedial measures.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other advantages of the present technique may becomeapparent upon reading the following detailed description and uponreference to the drawings wherein like reference numerals describe likeelements and wherein:

FIG. 1 is an exemplary pipeline network in accordance with certainaspects of the present techniques;

FIG. 2 is an exemplary embodiment of the control center of FIG. 1 inaccordance with aspects of the present techniques;

FIG. 3 is an exemplary embodiment of a pressure wave caused by a rupturein the pipeline network of FIG. 1.

FIG. 4 is an exemplary embodiment of a display shown to a pipelineoperator in the control center of FIG. 1 in accordance with aspects ofthe present techniques;

FIG. 5 is an exemplary embodiment of one the logic flow in one of theaspects of the present techniques.

DETAILED DESCRIPTION OF THE INVENTION

In the following detailed description and example, the invention will bedescribed in connection with its preferred embodiments. However, to theextent that the following description is specific to a particularembodiment or a particular use of the invention, this is intended to beillustrative only. Accordingly, the invention is not limited to thespecific embodiments described below, but rather, the invention includesall alternatives, modifications, and equivalents falling within the truescope of the appended claims.

The present invention is directed to a system and method for detectingthe occurrence of destabilizing events in one or more pipeline networks.The terminology “destabilizing event(s)” is intended to encompass anyevent or activity including but not limited to leaks, ruptures,equipment failures, equipment malfunction, process errors, etc that mayhave an adverse impact on the stable operation of the pipeline network.In particular, a real-time optimizer (RTO) is utilized with aSupervisory Control and Data Acquisition (SCADA) unit to detectdestabilizing events in the pipeline by detecting pressure reactionswithin the pipeline, comparing these reactions with empiricallydetermined acceptability for the current pipeline mode, eliminatingthose reactions caused by known pipeline events, using a method of sonardistancing to determine where the pressure reactions originated, andevaluating other real-time operational data to corroborate theoccurrence of a rupture. The RTO is an expert algorithm based controlsystem designed to optimize the safety and minimize the environmentalimpact of the pipeline due to destabilizing events while effectivelymanaging the generation of alarm events. To enhance the detection ofdestabilizing events in pipelines, the RTO analyzes concurrent orreal-time operational data from the SCADA unit. From the analysis, if apossible destabilizing event is detected, an alarm is generated via theSCADA unit to alert the operator of the pipeline network. Theinformation used to assess the possibility of a rupture may be providedto the operator either graphically, audibly or textually or anycombination thereof. It is contemplated that the system can recommend orautomatically execute corrective measures to minimize the impact ofdestabilizing events on the pipeline system and return the pipelinenetwork to stable operation.

Turning now to the drawings, and referring initially to FIG. 1, apipeline network 100 in accordance with some aspects of the presenttechniques is illustrated. In the pipeline network 100, a fluid, such asone or more fluid commodities (e.g., oil, gas and products producedtherefrom), is transported from a first facility 102 through variouspipeline segments 104 and pump stations 106 a-106 n to at least a secondfacility 108. The first facility 102 and second facility may be anyfacility associated with the production, processing and transporting ofoil, gas and/or products derived therefrom including but not limited toan oilfield production tree, surface facility, distribution facilities,oil sands plant or the like, an off-shore drilling platform, anoff-shore distribution or transportation terminal, refineries,petrochemical facilities, etc. The pipeline segments 104 may includetubular members to transport of fluid commodities therethrough. Itshould be noted that n may be any integer number and that thisembodiment is merely for exemplary purposes. For instance, otherembodiments may include single or multiple product strip or injectionpoints, branches in the pipeline, as well as any number of intermediatepump stations. The present invention is intended for use in varioustypes of pipeline networks having one or more branches.

The pump stations 106 a-106 n includes one or more pumps 110 a-110 n,one or more sensors 112 a-112 n, and/or one or more meters 108 a-108 n.The pumps 110 a-110 n may include one or more synchronous electricalmotor pumps, variable frequency drive (VFD) pumps and/or the like. Thepressure sensors 112 a-i 12 n are preferably located both upstream ofthe first pump 110 a-110 n and downstream of the last pump 110 a-110 nin each pump station 106 a-106 n, as shown in FIG. 1 and FIG. 3. Themeters 108 a-108 n are typically located only where the fluidcommodities enter or leave the pipeline network 100, as shown in FIG. 1.

To manage and monitor the operation of the pipeline network 100, variousprocessor based devices, such as remote monitoring devices 120, 121 and122 a-122 n, are utilized to collect and communicate data aboutoperational settings, which include equipment settings (e.g., equipmentstatus, etc.) and measured parameters (e.g., pressure, temperature, flowrate, etc.) of the pipeline network 100. The remote devices 120, 121 and122 a-122 n may be programmable logic controllers (PLCs), loopcontrollers, flow computers, remote terminal units (RTUs), human machineinterfaces (HMIs), servers, databases and/or a combination of thesetypes of processor based systems. These remote devices 120, 121 and 122a-122 n may also include monitors, keyboards, pointing devices and otheruser interfaces for interacting with an operator.

Each of the remote devices 120, 121 and 122 a-122 n may be located inone or more of the first facility 102, pump stations 106 a-106 n, andsecond facility 108 to collect data from the sensors 112 the operationaldata, such as operational settings or telemetry data, from the equipmentand/or meters 108 a-108 n associated with the pipeline network 100. Thecontrol signals from the equipment (e.g., pumps 110 a-110 n and/ormeters 108 a-108 n) and sensors 112 a-112 n may be limited by thedistance that the control signals may be transmitted by a switch ortransducer that is part of the equipment or meter 108 a-108 n. As such,each of the remote devices 120, 121 and 122 a-122 n may operate as acentral collection location for the data from one specific pump station106 a-106 n or other pipeline facility. As an example, the operationalsettings may include data about the draw rate, pump status, drag reduceradditive (DRA) injector status, valve status, DRA injection rate,variable frequency drive settings, flow rate in the pipeline segments104, height of fluid within tanks in the facilities 102 and 108, fluidtemperature; pressure in the pipeline segments 104, density of the fluidcommodity, and/or batch interface. The remote devices 120, 121 and 122a-122 n receive, process and store the various control signals in localmemory. In this manner, the operational settings for each location maybe efficiently managed for further distribution to the control center126.

The remote devices 120, 121 and 122 a-122 n interact with other devicesthat may be located at one or more control centers 126 via the network124 to further process the operational data. The control centers 126 mayinclude one or more facilities, which house various processor baseddevices having applications utilized to manage the equipment and monitorsensors 112 a-112 n or meters 108 a-108 n distributed along the pipelinenetwork 100. A control center 126 is shown in greater detail below inFIG. 2. Because each of the remote devices 120, 121 and 122 a-122 n andthe control centers 126 may be located in different geographiclocations, such as different structures, cities, or countries, a network124 provides communication paths between the remote devices 120, 121 and122 a-122 n and the control centers 126. The network 124 may comprisedifferent network devices (not shown), such as routers, switches,bridges, for example, may include one or more local area networks, widearea networks, server area networks, or metropolitan area networks, orcombination of these different types of networks. The connectivity anduse of the network 124 by the remote devices 120, 121 and 122 a-122 nand the devices within the control centers 126 is understood by thoseskilled in the art.

A control center 126 in accordance with aspects of the present inventionis illustrated in FIG. 2. The control center 126 is utilized to monitorand control the equipment and sensors 112 a-112 n in the pipelinenetwork 100. As a specific example of the operation performed by thecontrol center 126, pseudo code is listed below in Appendix A. Thecontrol center 126 includes a supervisory control and data acquisition(SCADA) unit 202 coupled to various control devices 214 a-214 n via anetwork 212. The SCADA unit 202 provides a pipeline operator with accessto operate the equipment in the pipeline network 100. While a singleSCADA unit 202 is illustrated, it should be appreciated that the controlcenter 126 may include one or more local or regional SCADA units and oneor more master SCADA units to manage the local SCADA units in othercontrol center architectures.

The SCADA unit 202 contains one or more modules or components thatperform specific functions for managing the transport of the fluidcommodities. For instance, the SCADA unit 202 may include a SCADAapplication 204 that includes one or more software programs, routines,sets of instructions and/or code to manage the operation of the pipelinenetwork 100. The SCADA application 204 may include OASyS DNA by TELVENT;Ranger by ABB, Inc.; Intellution by GE, Inc.; and/or UCOS by ControlSystems International (CSI), Inc. The SCADA unit 202 includes a datacommunication module 206 and a database 208. The data communicationmodule 206 includes a set of instructions that manage communicationswith other devices (e.g., request the operational settings from theremote devices 120, 121 and 122 a-122 n at specific intervals or provideequipment settings to the devices 120, 121 and 122 a-122 n). Thedatabase 208 may be of any conventional type of computer readablestorage device used for storing data, which may include hard diskdrives, floppy disks, CD-ROMs and other optical media, magnetic tape,and the like, which stores the operational settings. The SCADAapplication 204 analyzes the operational settings, which may includeconverting the operational settings into a specific format forpresentation to operators and/or identifying alarm conditions. Theresults of this analysis, along with the operational settings, are thenstored in the database 208, as operational settings and operationalreports. Then, the operational settings and operational reports may besynchronized to other databases of additional SCADA units in otherlocations.

In addition, the operational settings and operational reports may bepresented to processor based devices, such as control devices 214 a-214n, via the network 212 to provide an operator with data about thereal-time operation of the pipeline network 100. The control devices 214a-214 n may be computers, servers, databases and/or a combination ofthese types of processor based systems, which may also include displayunits (e.g. monitors or other visual displays), keyboards, pointingdevices and other user interfaces for interacting with the operator. Thenetwork 212, which may include similar components to the network 124,may be utilized to provide communication paths between the controldevices 214 a-214 n and the data communication module 206 in the SCADAunit 202. Typically, the network 212, which may include differentnetworking devices (not shown), may include one or more local areanetworks or server area networks, but may also include wide areanetworks, metropolitan area networks, or combination of these differenttypes of networks for certain operations. The connectivity and use ofthe network 212 by the control devices 214 a-214 n and the SCADA unit202 is understood by those skilled in the art.

To operate the pipeline network 100, the operator enters operationalinstructions into one of the control devices 214 a-214 n. Theseoperational instructions, which may include equipment settings or flowrates or operating modes (i.e., tight line mode or draw mode), forexample, are communicated to the SCADA application 204 through the datacommunication module 206 in the SCADA unit 202. The SCADA unit 202stores the operational instructions in the database 208 and maysynchronize the operational instructions with other SCADA units. TheSCADA application 204 analyzes the operational instructions and convertsthe operational instructions into equipment settings, which may be inthe same or a different format that is accepted by the remote devices120, 121 and 122 a-122 n. The SCADA application 204 converts theoperational instructions from units of measurement for the operator intounits of measurement for the remote devices 120, 121 and 122 a-122 n.The equipment settings are then transmitted to the remote devices 120,121 and 122 a-122 n by the data communication module 206. Once received,the remote devices 120, 121 and 122 a-122 n acknowledge the equipmentsettings and transmit the equipment settings by providing theappropriate control signal to the equipment. The equipment settings(e.g. opening or closing flow control devices, starting or stoppingpumps, and/or starting or stopping DRA injectors to adjust the rate DRAis being injected into the pipeline segments 104) are then executed bythe respective equipment.

For the pipeline network 100 to operate efficiently, and carry a largevolume of fluid from one facility 102 to another facility 108 the pumps110 a-110 n are used to raise the pressure in the pipeline to pressurelevels much greater than that of the atmosphere surrounding the pipelinesegments 104 and pump stations 106 a-106 n. This pressure differentialplaces stresses on the various elements of the pipeline network 100 usedto contain the fluid being transported. As a consequence of thesepressures, it is possible that the elements containing the pressuredifferential, and in particular compromised areas (corrosion) or lowerrated pipeline elements, may rupture, as shown in FIG. 3, below. It isalso possible that the pipeline equipment contained in the pumpingstations and elsewhere may fail or operate improperly, which can createunstable operating conditions that may lead to a possible rupture.Furthermore, unstable operation could result from improper operationalinstructions entered into by one of the control devices 214 by thepipeline operator or the failure of the operator to adjust the necessaryoperational instructions in response to a change in operating mode or achange in the fluid within the pipeline.

When an element of the pipeline network 100 ruptures 300, the pressureat the rupture location rapidly changes, as the first molecules of fluidare pushed from the pipeline by the pressure differential. This pressurechange causes pressure in the fluid adjacent to the rupture to change inresponse to the initial pressure change. This effect is carried throughthe pipeline network 100 as a pressure, shock or sound wave 301. Thepressure wave 301 travels through the fluid at a speed relative to thesonic characteristics of the fluid or chain of batched fluids (gaseousor liquid) along the pipeline's length, so that the time the pressurewave 301 travels is mathematically relatable to the distance it hastraveled. The operation of a pump 110 or other pipeline component maycreate a pressure or sound wave, which travels through the pipeline in asimilar manner. The unstable operation of the pipeline may also create apressure or sound wave within the pipeline. Such a wave may not be ashigh as those associated with a rupture.

Many of the prior art systems, some described above, designed to detectruptures in the pipeline network typically do not use detection of apressure wave in their analysis. These systems depend on a balancingalgorithm to determine if fluid is leaving the pipeline at an un-meteredlocation to determine if there is a rupture. As may be appreciated,these prior art systems require that a sufficient volume of fluid hasleft the pipe through the rupture before detection of the rupture canoccur. This can result in a significant environmental impact in the areasurrounding the rupture as inferential measurement systems arecommonplace and relatively lethargic with respect to hydraulicwavespeeds and the ensuing segmental decompressions that follow ruptureevents in closed pressurized hydraulic networks. The systems that dosense acoustic waves described above only isolate ruptures and not otherdestabilizing events that impact the stable operation of the pipelinenetwork.

To provide near real-time detection of a destabilizing event including arupture 300, and thus allow more rapid and effective action, a real-timeoptimizer (RTO) 210 is utilized for analyzing operational settingswithin a SCADA unit 202. This enhances the operation of the pipelinenetwork 100 in real-time to respond more effectively to destabilizingevents.

The RTO 210 may be implemented as one or more software programs,routines, software packages, and/or computer readable instructions thatinteract with the SCADA unit 202, or specifically the SCADA application204 and database 208. The RTO 210 may also be written in any suitablecomputer programming language. Through the RTO 210, additionalfunctionality may be provided to the operator to provide reports andother notifications (whether visual or audible) of suspected pipelinedestabilizing events including ruptures 300 through the detection andanalysis of pressure waves 301. These notifications will allow theoperator to respond to high level destabilizing events and lower levelevents that, if left ignored, could ultimately result in a high leveldestabilizing event including a rupture.

To obtain information regarding pressure waves for analysis, the RTO 210requires the collection of additional information, which may becollected and processed by remote devices 120, 121, and 122 a-122 n.Unlike prior art systems with predetermined sampling at fixed intervals,the sampling for pressure waves occurs at the highest rate permitted bythe pressure transmitter sensors 112. This significantly reduces thelikelihood of a pressure wave going undetected. The electricalrepresentation of the pressure reported by the pressure sensors 112a-112 n to the remote devices 120, 121, and 122 a-122 n is typicallymeasured and processed by the remote devices 120, 121, and 122 a-122 nat a high rate of speed (for example, every 50 milliseconds). Thisdiffers from existing pipelines, where previous values are typicallydiscarded and values are transmitted to the control center 126 much lessfrequently, for example every ten seconds. As a result, theimplementation of the system according to the present invention mayrequire modification of the remote devices 120, 121, and 122 a-122 n toperform statistical calculations on the pressure values. Specifically, astandard deviation may be calculated for the pressure values collectedduring a short period of time (for example, 15 seconds). In accordancewith the present invention, the calculated standard deviation is of arolling nature. For example, the standard deviation is calculated usingpressure values collected between times t1 and t5. The next standarddeviation is calculated using pressure values collected between times t2and t6. The next standard deviation is calculated using pressure valuescollected between times t3 and t7. All subsequent deviations arecalculated in this rolling manner. By contrast, the prior art systemsreview their obtained acoustic information in fixed intervals (e.g., t1to t5, t6-t10, t11-t15). With such a review, destabilizing events thatstart in one period and end in another period can be overlooked. Therolling calculation of the standard deviation in accordance with thepresent invention avoids this occurrence. The present invention is notintended to limited to the use of an empirically computed standarddeviation; rather, numerous empirically based determinations (which arenot based on force fit models) including but not limited to derivativefunction (1^(st), 2^(nd) and 3^(rd) derivatives), integral functions arewell within the scope of the present invention.

An operational setting is established, such that the field devices 120,121, and 122 a-122 n have available for their analysis a numberrepresenting a multiplier to be applied to the calculated standarddeviation. Should the pressure sensors 112 a-112 n then report apressure which exceeds the standard deviation calculated with themultiplier applied, the remote device 120, 121, and 122 a-122 n willdeclare the detection of a pressure wave 301. The normal hydraulic noisewithin pipeline systems produce a particular standard deviationcharacter for the pipelines typical modes of operation while adestabilizing events such as loss of pipeline integrity (rupture) willproduce a uniquely different standard deviation character than thefamily of normal mode standard deviation characters. Similarly, thestart-up or shutdown of a pump or an unstable operation of the pipelinewill produce a uniquely different standard deviation character than thefamily of normal mode standard deviation characters.

In order to correlate pressure waves 301 between different pressuresensors 112 a-112 n, it is important to have an accurate measurement oftime which is synchronized between all the remote devices 120, 121, and122 a-122 n on the pipeline network 100. This is accomplished byproviding a receiver and appropriate additional electronics within theremote device 120, 121, and 122 a-122 n to allow highly accurate timesynchronizing updates to be collected from the transmissions ofsatellites used for Global Positioning Systems and provided to the logicunit of the remote device 120, 121, and 122 a-122 n.

As noted above, pressure waves 301 may be caused in the pipeline network100 through other means which are considered part of normal pipelineoperations, including but not limited to the starting and stopping ofpumps 110 a-110 n and the opening and closing of valves. It is importantthat the pressure waves 301 caused by these events to be taken intoconsideration by adjusting the alarm triggering thresholds in real timeor removing it from those being considered for rupture detection. Thismay be done at the remote device 120, 121, and 122 a-122 n for thoseevents that are initiated by the same remote device 120, 121, and 122a-122 n that detected the pressure wave. Logic may be added to theremote device 120, 121, and 122 a-122 n to disable pressure wavedetection for a certain period of time following an adjustment to anequipment setting that would result in a pressure wave. Alternatively,the triggering thresholds for a destabilizing event can be adjusted(i.e., raised or lowered) in response to the normal operating eventssuch that destabilizing events may still be detected while accountingfor the normal operating conditions. Superior possible methods includecharacterizing normal pipeline operating events under high speed trendanalysis and build a comparative matrix of normal pipeline actioncharacters and by reviewing these hydraulic signatures with empiricallydetermined standard deviation thresholds providing an enhanceddiscrimination of destabilizing events from normal pipeline operatingevents and noise. This will provide an effective tool for managing thegeneration of alarms (i.e., false alarms) by the system,

As mentioned above, during normal operation of the pipeline network,various pressure waves are generated that are not attributable to adestabilizing event, but nonetheless create pressure activity that couldgenerate an alarm signal. The control center 126 and remote devices 120,121, 122 can factor in pressure waves attributed to normal pipelineoperation. These waves can be discounted with the necessary adjustmentto the alarm triggering thresholds to reduce the number of false alarmsgenerated. Current monitoring systems generate thousands of alarms in agiven day of pipeline operation. Many of these alarms are false, whichresult in operators either clearing or ignoring low level alarms. Thisnot only reduces the amount of time an operator spends addressing eachalarm, but also desensitizes the operator to respond to low levelalarms. The discounting of pressure waves associated with known pipelineoperations, their acceptable reactions, and the adjustment of thetriggering thresholds thereto can be effectively reduced by at least 60%and more preferably by at least 80%. This represents a significantreduction in the generation of hydraulical alarms, which provides theoperator with more time to respond to actual alarms and also respond tolow level alarms indicating unstable operation before the unstableoperation leads to higher level alarms and potential damage to thepipeline.

In order to provide the information regarding the detection of pressurewaves to the RTO 210, the remote devices 120, 121, and 122 a-122 ninteract with Data Communication Module 206, the SCADA Application 204and into the database 208. From there the RTO 210 retrieves the data asneeded by its algorithms.

Once a pressure wave report has been received, the RTO 210 waits apredetermined period of time for the particular instance of the pipelinenetwork 100 for other pressure wave reports to be made available. Thepressure wave from a destabilizing event may cause more than onepressure wave report, and having two or more reports is necessary todetermine the location of the destabilizing event(s). The time period towait is determined by dividing the length of the pipeline by the speedof sound in the fluid contained in the pipeline.

Pressure waves caused by normal operation of pipeline equipment are tobe ignored by the RTO 210. These pressure waves are considered “UsualSuspects”, whether by reviewing the Usual Suspects' hydraulic characterfor normalcy or by momentarily masking normal pipeline equipment actionsfrom RTO2. To do this, the RTO 210 maintains a table listing the variousnormal, operational pipeline activities that cause a pressure waves 301and stores within that table the time it would take a pressure wave 301caused by that activity to reach each of the pressure sensors 112 a-112m on the pipeline network 100. The RTO 210 must compare each of thepressure waves 301 reported by the pressure sensors 112 a-112 n withrecent activity on the pipeline, removing them from consideration fordestabilization event detection if the time of receipt indicates thatthey originated during a pipeline activity. Specific examples of theoperation of the RTO 210 to identify and update Usual Suspects areillustrated as pseudo code under “Update Usual Suspects” and “Is a UsualSuspect” in Appendix A. The prior art systems compare the sensed wave tostored leak profiles. These systems, however, have limited capabilitiesbecause each leak may have a unique profile. As such each leak may notbe identified. Unlike the prior art systems, the present inventioncompares pressure waves to normal operating conditions or normaloperating events not predetermined leak profiles. As such, the presentinvention can more accurately detect an abnormal operating conditionwith greater accuracy.

Having assembled a list of pressure waves 301 that occurred during theperiod it would take such a wave to transit the pipeline, the RTO 210must attempt to identify a bracketing pair of wave detections. That is,two wave detections from different pump stations 106 a-106 n, one oneither side of the rupture 300. The rupture will be located betweenthese two stations. This may be done by arranging the detections inchronological order, and then selecting the first two from uniquestations 106 a-106 n while accounting for any sonic wavespeed characterdifferences of fluids either side of the event on batched networks. Thedetermination of whether this pair of detections is bracketing may thenbe determined using the following equation:

If (t ₂ −t ₁)≦t ₂₁

Then the pair is a bracketing pair

Where t₂=time of the second detection

-   -   t₁=time of the first detection; and    -   t₂₁=time for a wave to travel from the station of the second        detection to the station of the first detection.        That is, if the time differential is not great enough for the        wave 301 to travel from one station 106 a-106 n to the other,        then the origination of the wave 300 must be between the        stations. Should the chosen pair not prove to be a bracketing        pair, then each additional pair must be examined in turn to        attempt to identify a bracketing pair.

The identification of a bracketing pair of wave detections provides amethod to determine the location of the origin of the wave 300 (orsuspected rupture). The following formula may be employed to make thisdetermination:

d ₂=0.5*[d ₁₂+(t ₂ −t ₁)*ws]

where d₂=distance from pump station 106 a-106 n where second detectionoccurred towards pump station 106 a-106 n where first detectionoccurred.

-   -   t₂=time of second detection    -   t₁=time of first detection    -   d₁₂=distance from pump station where second detection occurred        and pump station where first detection occurred.    -   ws=wave speed (speed of sound in fluid)

The detection of a pressure wave 301 not due to operational activity bytwo stations which are not bracketing cannot be used to determine theorigin of the pressure wave 301, however, it still provides morelocation information than a single pressure wave detection. In thiscase, the RTO 210 can determine which side of a station 106 a-106 n thepressure wave 301 originated, by comparing the two times the pressurewave 301 was received. This can be accomplished in the following manner.If the pressure wave 301 is detected by a sensor located on a first sideof the station 106 before it is detected on a corresponding sensor on anadjacent second side of the station 106, then the origin of the pressurewave is on the first side of the station 106. If the pressure wave 301is detected by a sensor located on the second side of the station 106before it is detected on the corresponding sensor on the first side ofthe station 106, then the origin of the pressure wave is on the secondside of the station 106.

The RTO 210 also provides analysis on the trend of the pressures tocorroborate the results of the pressure wave detection. One method tocorroborate a destabilizing event leak along with the initial eventsignature detection is to compare the slope of the subject segment'snodal pressures from before the pressure wave 301 with the slope of thesame nodal pressures from after the pressure wave 301. The slope of thepressure is calculated by the RTO 210 by storing a number of values ofthe pressure from predetermined and meaningfully brief time intervals.The slope is then determined by the following equation:

Slope=(latest pressure value−oldest pressure value)/(current time−oldesttime)

The slope prior to the pressure wave 301 is compared with the slopeafter the pressure wave 301. If the slope has decreased by a valuegreater than that of a pre-configured parameter, the trend of thepressure has changed as a result of the pressure wave 301, and thisinformation corroborates the possibility of a rupture 300 or otherdestabilizing event. Other mathematical or statistical approaches areusable (such as rate of change, sum of deltas, or combinations thereof).

The RTO 210, if metering is available, may also provide analysis on thetrend of the net flow of fluid through the pipeline network 100 tocorroborate the results of the pressure wave detection. The trend isdetermined by obtaining the measured flow rates from the meters 108a-108 n at all entries and exits to the pipeline network 100 and summingthem (in flow positive, out flow negative). A specific example of theoperation performed by the RTO 210 is illustrated as pseudo code as“store line flow data” under “RTO Event Detection” in Appendix A. Theresults of this summation are then compared for before the pressure wave301 and after the pressure wave 301. If the summation has increased by avalue greater than that of a pre-configured parameter, the trend of thenet flow has changed as a result of the pressure wave 301, and thisinformation corroborates the possibility of a rupture 300 or otherdestabilizing event.

If the SCADA Application 204 is providing a line balance function, whichis a traditional method of leak detection, done by comparing volumeentering and leaving the pipeline network 100 with the volume in thepipeline network 100 then the RTO 210 can perform yet anothercorroboration. A typical line balance function will make available tothe RTO 210 through the database 208, a value, known as the line balancedivergence, representing the change in the imbalance of the line balancecalculation over a short period of time, typically a few minutes. TheRTO 210 provides analysis on the trend of the line balance divergence tocorroborate the results of the pressure wave detection. The trend isdetermined by comparing the slope (or other mathematical or statisticalcomparison) of the line balance divergence over time from before thepressure wave 301 with the slope of the line balance divergence overtime from after the pressure wave 301. The slope of the line balancedivergence is calculated by the RTO 210 by storing a number of values ofthe line balance divergence for predetermined time intervals. Under theexemplary method, the slope is then determined by the followingequation:

Slope=(latest line flow divergence value−oldest line flow divergencevalue)/(current time−oldest time)

A specific example of this operation of the RTO 210 is illustrated aspseudo code under “Get Line Flow Data” in Appendix A. The slope prior tothe pressure wave 301 is compared with the slope after the pressure wave301. If the slope has increased by a value greater than that of apre-configured parameter, the trend of the line balance divergence haschanged as a result of the pressure wave 301, and this informationcorroborates the possibility of a rupture 300. Beneficially, thiscorroboration will occur prior to the line balance function determiningthat there is a rupture 300. As multiple independent corroborating datapermits a lower indicative line balance divergence to further supportrupture likelihood.

The RTO 210, by placing data into the database 208, notifies theoperator of the pipeline that a possible destabilizing event hasoccurred based on pressure wave detection and other corroboratingevidence. This includes the creation of an incident report. A specificexample of the operation performed by the RTO 210 is illustrated aspseudo code under “Create Incident Report” in Appendix A. The RTO 210may report different levels of certainty to the operator based on thelevel of evidence available. An exemplary set of reporting levels isshown further in Table 1 below. Level 1 represents the highest level ofcertainty that a rupture 300 has occurred, while Level 4 represents alower level of certainty. As the RTO 210 obtains further evidence thelevel being reported to the pipeline network 100 operator may change.

TABLE 1 Two Two Two Two Trigger Trigger Trigger Trigger Bracketed SameOne Bracketed Not One Trigger Station Sided Spanned Spanned No No LineNo Line Level 4 Level 4 Level 4 Level 4 Level 2 Pressure Flow BalanceDecay Divergence Line Level 4 Level 4 Level 4 Level 4 Level 2 BalanceLine Flow No Line Level 4 Level 4 Level 4 Level 4 Level 2 DivergenceBalance Line Level 4 Level 4 Level 4 Level 4 Level 2 Balance Pressure NoLine No Line Level 2 Level 2 Level 2 Level 2 Level 1 Decay Flow BalanceDivergence Line Level 2 Level 2 Level 2 Level 2 Level 1 Balance LineFlow No Line Level 1 Level 1 Level 1 Level 1 Level 1 Divergence BalanceLine Level 1 Level 1 Level 1 Level 1 Level 1 Balance

FIG. 4 is an exemplary flow chart depicting the use of the RTO 210 inthe pipeline network 100 with the SCADA unit 202. An operator of theSCADA unit 202 may utilize the RTO 210 to monitor the destabilizingevent detection for the pipeline network 100, as described below.

The operation of the system in accordance with the present inventionwill now be described in connection with FIG. 4. The operation isinitiated at step 402. A timer is then started in Step 404 to allow forlater re-execution of the logic at short time intervals. The datacollected, stored in database 208 and used for line flow trend analysisis updated at Step 406 to provide corroborating evidence for anypossible destabilizing event detections. The data produced by the linebalance functionality of the SCADA Application 204 is then collected andanalyzed in Step 408 for possible future use in corroboratingdestabilizing event detections. The current pressures are retrieved fromthe database 208 in Step 410, stored within the RTO 210 and analyzed forfuture use in corroborating destabilizing event detections. Any newlyreceived pressure wave reports are evaluated in Step 412 against changesin measured parameters in the pipeline network 100 to determine whetheror not the pressure wave report was caused by operational activity. Ifthe wave report was caused by operational activity, it is removed fromthe list of pressure waves 300 to be analyzed by the RTO 210.

In Step 414 a determination is made whether or not the RTO 210 iswaiting to receive additional pressure wave detection reports associatedwith a previously received report. The waiting time in Step 414 differsfrom the timer set in Step 404. The period is shorter. The waiting timein Step 414 is based upon the wave speed length. The waiting time is setbased upon slowest possible wave speed. If a pressure wave is detected,then the waiting time will be based upon the time it would take toreceive another pressure wave if such pressure wave had the slowestpossible wave speed. If the determination is yes and the RTO 210 iswaiting for associated reports, then the operation of the systemproceeds to Step 416. If the determination is negative (i.e., noassociated pressure reports are received) then the operation of thesystem proceeds to Step 426, which is discussed in greater detail below.

In Step 416, the counter associated with waiting for associated reportsis decremented. This counter is then examined in Step 418 to determineif the waiting period has expired. If the waiting period has expired andan associated pressure wave report is received, then all of the receivedpressure wave reports will be processed in Step 420 to determine whetherthere are bracketing detections, or a single detection, the possibleassociated location and alarm level. In Step 422, a determination ismade as to whether or not the analysis performed in Step 420 found apossible rupture. If a possible destabilizing event was found, theoperation proceeds to Step 424 where an incident report is created, asshown in FIG. 5 and the corroborating factors examined to determine ifcorroboration has occurred. A notice and/or an automatic soft pipelinespooldown, or corrective measure algorithm is executed along with theincident report such that the operator of the system can takeappropriate measures to isolate the leak and limit spills from thepipeline. The operation of the system then proceeds to Step 430 wherethe system waits until the timer activated in Step 404 expires. Theoperation then returns to Step 404 where the process is repeated. If nopossible destabilizing event is identified, then the operation proceedsto Step 430 where the system waits until the timer activated in Step 404expires. The operation then returns to Step 404 where the process isrepeated.

Returning to Step 414, if it is determined that the RTO 210 was notwaiting for associated reports, then the operation of the systemproceeds to Step 426 to determine if a new pressure wave detection hasbeen received. If no pressure wave detection is received, the operationof the system proceeds to Step 430 where the system waits for the timerset in Step 404 to expire. The steps are then repeated with the settingof the timer in Step 404. If a new pressure wave detection is receivedin Step 426, the operation of the system proceeds to step 428 where theinitialization of the data records for tracking the new pressure wave,the setting of a timer to wait for associated pressure wave detections,and the saving of the pre-detection corroboration values for futureanalysis occurs. The operation of the system then proceeds to Step 430,where the system waits in the manner described above.

As discussed above in connection with Step 424, an incident report iscreated when a pressure wave reports indicates the occurrence of anevent. The incident report may be presented via a graphical userinterface to a display unit for the operator. An audible notificationmay also be provided. The graphical user interface may be a windowprovided to the operators via the SCADA unit 202, which includesgraphical or textual data, a report or any other suitable data. Anexample of the graphical user interface is illustrated in FIG. 5.

The screen view is merely one example of an incident report that may bepresented to an operator. As can be appreciated, additional operationalsettings and data may be presented in other embodiments.

The screen view in FIG. 5 is divided into various windows or sections.For instance, section 500 reports the date and time at which the firstpressure wave detection occurred. Section 502 reports the current alarmlevel assigned to the pressure wave detection using the customizablealarm level matrix presented in Table 1, above. Because the alarm levelassigned to the analysis of a possible destabilizing event detection maychange over time, as more corroboration evaluation is completed, thedate and time at which each level of alarm was reached is displayed insection 504. If a certain level of alarm was not reached for aparticular detection, it is not displayed in this section.

Section 506 is used to track and report whether the investigationlaunched by the operator has been completed or not. If the analysis bythe RTO 210 was able to determine a location (bracketing detections, ortwo detections on one side of the rupture) this is reported in section508. Section 510 provides detailed information on the pressure wavedetection(s) that were used to arrive at the location by the RTO 210during its analysis. Section 512 reports the status of the pressuredecay corroboration for the upstream station used in the detection, ifit exists, whether it is still in progress, or if complete, whethercorroboration was found or not. Section 514 reports the status of thepressure decay corroboration for the downstream station used in thedetection, if it exists, whether it is still in progress, or ifcomplete, whether corroboration was found or not. Section 516 reportsthe status of the line flow divergence corroboration, whether it isstill in progress, or if complete, whether corroboration was found ornot. Section 518 reports the status of the line balance divergencecorroboration, whether it is still in progress, or if complete, whethercorroboration was found or not.

As discussed above, the system in accordance with the present inventionis effective in managing the generation of alarms in order to reduce thenumber of false alarms. In addition, it is contemplated that the presentinvention is useful in connection with diagnosing destabilizing eventsand recommending or automatically executing potential remedial measures.As discussed above, the system is useful in identifying the presence andlocation of both high level and lower level destabilization events. Thecontrol center 126 can evaluate the data which resulted in thegeneration of an alarm for a destabilizing event via an expert basedpipeline diagnostic subroutine that considers the current destabilizedcharacter of the pipeline against the expert system's empiricalknowledge of what the current mode's hydraulic character should looklike while cross referencing all SCADA-known setpoint and equipmentstatus against this preferred and expected character, the expert systemcould then automatically execute a corrective measure algorithm or, ifpreferable, issue a corrective measure notice to the human to addressthe low level alarm before the lower level destabilizing event escalatesinto a high level destabilizing event with potential catastrophic impacton the pipeline. It is also contemplated that the control center 126 caninitiate a remedial or corrective measure to respond to destabilizingevents to maintain stable operation.

It will be apparent to those skilled in subjects related to the art thatvarious modifications and/or variations may be made without departingfrom the scope of the present invention. While the present invention hasbeen described in the context of a pipeline, the present invention isnot intended to be so limited; rather, it is contemplated that thepresent invention can be used in piping found in refining andpetrochemical processing operations, upstream and explorationoperations, and any other operation outside of the oil and gas fieldthat is concerned with managing the stable operation of a pipeline andthe fluids flowing therethrough. Thus, it is intended that the presentinvention covers the modifications and variations of the method herein,provided they come within the scope of the appended claims and theirequivalents.

1. A method of real time monitoring a pipeline network to identifypossible destabilizing events in the pipeline network, comprising:sensing one or more pressure waves within the pipeline network atpredetermined locations within the pipeline network; and determining thepresence of a possible destabilizing event in the pipeline network inresponse to the sensed pressure waves by detecting variations in thesensed pressure waves, and determining whether or not the detectedvariation exceeds an accepted standard deviation.
 2. The methodaccording to claim 1, wherein the accepted standard deviation is anempirically determined standard deviation.
 3. The method according toclaim 1, wherein determining the presence of a possible destabilizingevent in the pipeline network in response to the sensed pressure wavesfurther comprising: determining whether or not a subsequentialdecompression characteristic is present following the detection of thevariation in sensed pressure waves.
 4. The method according to claim 3,further comprising: issuing an alarm indicating the presence of a leakwhen it is determined that the subsequential decompressioncharacteristic is present.
 5. The method according to claim 1, whereindetermining the presence of a possible destabilizing event in thepipeline network in response to the sensed pressure waves furthercomprising: determining whether or not the sensed pressure waves exceeda predetermined stable operating threshold.
 6. The method according toclaim 5, wherein the predetermined stable operating threshold isautomatically adjusted based upon at least one of the current operatingmode, current operating conditions and current operating events.
 7. Themethod of monitoring a pipeline network according to claim 1, furthercomprising: determining the certainty of the possible destabilizingevent.
 8. The method according to claim 7, wherein determining thecertainty of the possible destabilizing event includes comparing thedetermination of a possible destabilizing event based upon sensedpressure waves with one or more sensed pipeline network operatingconditions.
 9. The method of monitoring a pipeline network according toclaim 7, further comprising: generating an alarm reporting the presenceand certainty of the possible destabilizing event.
 10. The methodaccording to claim 9, further comprising: managing the generation ofalarms.
 11. The method of monitoring a pipeline network according toclaim 1, further comprising: determining the location of the possibledestabilizing event in the pipeline network in response to the sensedpressure waves.
 12. The method of monitoring a pipeline networkaccording to claim 11, further comprising: generating an alarm reportingat least one of the presence and location of the possible destabilizingevent.
 13. The method of monitoring a pipeline network according toclaim 11, wherein the sensing of pressure waves within the pipelinenetwork occurs at periodic intervals, and wherein determining thelocation of the possible destabilizing event in the pipeline network inresponse to the sensed pressure waves comprising: identifying whichpredetermined locations a sensed pressure wave is sensed at a firstsensing time; identifying which predetermined locations the sensedpressure wave is sensed at a second sensing time; and determining thelocation of a possible destabilizing event based upon the location ofthe sensed pressure wave at the first sensing time and the secondsensing time.
 14. The method according to claim 1, further comprising:identifying a potential cause of the sensed destabilizing event bycomparing the character of the current destabilizing events using anexpert based diagnostic subroutine with prior destabilizing events, thecurrent operating mode of the pipeline network, the current operatingconditions in the pipeline network and the current operating events inthe pipeline network.
 15. The method according to claim 14, furthercomprising: reporting the potential cause of the sensed destabilizingevent.
 16. The method according to claim 15, further comprising:determining at least one corrective measure in response to the senseddestabilizing event; and performing at least one of reporting the atleast one corrective measure to an operator of the pipeline network andautomatically executing the at least one corrective measure.
 17. Amethod of real time monitoring a pipeline network to identify possibledestabilizing events in the pipeline network, comprising: sensing one ormore pressure waves within the pipeline network at predeterminedlocations within the pipeline network; and determining the presence of apossible destabilizing event in the pipeline network in response to thesensed pressure waves by determining whether or not the sensed pressurewaves exceed a predetermined stable operating threshold, wherein thepredetermined stable operating threshold is automatically adjusted basedupon at least one of the current operating mode, current operatingconditions and current operating events.
 18. The method according toclaim 17, further comprising: determining the certainty of the possibledestabilizing event.
 19. The method according to claim 18, whereindetermining the certainty of the possible destabilizing event includescomparing the determination of a possible destabilizing event based uponsensed pressure waves with one or more sensed pipeline network operatingconditions.
 20. The method according to claim 18, further comprising:generating an alarm reporting the presence and certainty of the possibledestabilizing event.
 21. The method according to claim 20, furthercomprising: managing the generation of alarms.
 22. The method accordingto claim 17, further comprising: determining the location of thepossible destabilizing event in the pipeline network in response to thesensed pressure waves.
 23. The method according to claim 22, furthercomprising: generating an alarm reporting the presence and location ofthe possible destabilizing event.
 24. The method according to claim 22,wherein the sensing of pressure waves within the pipeline network occursat periodic intervals, and wherein determining the location of thepossible destabilizing event in the pipeline network in response to thesensed pressure waves comprising: identifying which predeterminedlocations a sensed pressure wave is sensed at a first sensing time;identifying which predetermined locations the sensed pressure wave issensed at a second sensing time; and determining the location of apossible destabilizing event based upon the location of the sensedpressure wave at the first sensing time and the second sensing time. 25.The method according to claim 17, further comprising: identifying apotential cause of the sensed destabilizing event by comparing thecharacter of the current destabilized events using an expert baseddiagnostic subroutine with at least one of the prior destabilizingevents, the current operating mode of the pipeline network, the currentoperating conditions in the pipeline network and the current operatingevents in the pipeline network.
 26. The method according to claim 25,further comprising: reporting the potential cause of the senseddestabilizing event.
 27. The method according to claim 26, furthercomprising: determining at least one corrective measure in response tothe sensed destabilizing event; and one of reporting the at least onecorrective measure to an operator of the pipeline network andautomatically executing the at least one corrective measure.
 28. Amethod of managing the generation of alarms for possible destabilizingevents in a pipeline network, comprising: sensing one or more pressurewaves within the pipeline network at predetermined locations within thepipeline network; automatically adjusting a predetermined stableoperating threshold for the pipeline network at the predeterminedlocations based upon at least one of the operating mode of the pipelinenetwork, current operating conditions in the pipeline network andcurrent operating events in the pipeline network; determining thepresence of a possible destabilizing event in the pipeline network bydetermining whether or not the sensed pressure waves exceed the adjustedpredetermined stable operating threshold; and generating an alarmindicating the possible presence of a destabilizing event when thesensed pressure waves exceed the adjusted predetermined stable operatingthreshold.
 29. The method according to claim 28, wherein determining thepresence of a possible destabilizing event in the pipeline network inresponse to the sensed pressure waves further includes detectingvariations in the sensed pressure waves, and determining whether or notthe detected variation exceeds an accepted standard deviation.
 30. Themethod according to claim 29, wherein the accepted standard deviation isan empirically determined standard deviation.
 31. The method accordingto claim 28, wherein generating an alarm indicating the possiblepresence of a destabilizing event further comprising generating an alarmindicating the possible presence of a destabilizing event when thesensed pressure waves exceed the adjusted predetermined stable operatingthreshold and the detected variation exceeds the accepted standarddeviation.
 32. The method according to claim 28, wherein determining thepresence of a possible destabilizing event in the pipeline network inresponse to the sensed pressure waves further comprising: determiningwhether or not a subsequential decompression characteristic is presentfollowing the detection of the variation in sensed pressure waves. 33.The method according to claim 32, wherein generating an alarm indicatingthe possible presence of a destabilizing event includes generating analarm indicating the presence of a leak when it is determined that thesubsequential decompression characteristic is present.
 34. A system formonitoring a pipeline network, wherein the pipeline network having afirst facility, a second facility, at least one pipeline segmentconnecting the first facility and the second facility such that thefluid can flow between the first facility and the second facility, andat least one pumping station connected to the at least one pipelinesegment, whereby fluid flowing through the at least one pipeline segmentflows through the at least one pumping station, the system comprising: aplurality of pressure sensing devices for sensing the presence of one ormore pressure waves within the pipeline network; a plurality of remotemonitoring devices operatively connected to the first facility, thesecond facility and the at least one pumping station, wherein the remotemonitoring devices monitor the operation of the pipeline network andcollect operating data of the pipeline network, wherein each of theplurality of pressure sensing devices being operatively connected to atleast one remote monitoring device; and a control unit operativelyconnected to the plurality of remote monitoring devices for monitoringthe operation of the pipeline network based upon signals received fromthe plurality of remote monitoring devices, wherein the control unitdetects the presence of possible destabilizing events in the pipelinenetwork by determining whether or not variations in the sensed pressurewaves are present and whether or not the variation exceeds an acceptedstandard deviation.
 35. The system according to claim 34, wherein thecontrol unit empirically determines the accepted standard deviation. 36.The system according to claim 34, wherein the control unit furtherdetermines the presence of a possible destabilizing event by determiningwhether or not the sensed pressure waves exceed a predetermined stableoperating threshold.
 37. The system according to claim 36, wherein thecontrol unit adjusts the predetermined stable operating threshold inresponse to at least one of the operating mode, current operatingconditions and current operating events.
 38. The system according toclaim 34, wherein each of the at least one pumping station includes apump, wherein the plurality of pressure sensing devices comprising: apair of pressure sensing devices for each pumping station, wherein afirst sensing device of the pair of pressure sensing devices is locatedon one side of the pump in the at least one pipeline segment and asecond sensing device of the pair of pressure sensing devices is locatedon an opposite of the pump in the at least one pipeline segment, andwherein each pressure sensing device being capable of sensing one ormore pressure waves within the pipeline network.
 39. The systemaccording to claim 34, wherein the control unit determines the certaintyof the possible destabilized event by comparing the determination of apossible destabilized event based upon sensed pressure waves with one ormore sensed pipeline network operating conditions sensed by theplurality of remote monitoring devices.
 40. The system according toclaim 34, wherein each of the at least one pumping station includes apump, wherein the plurality of pressure sensing devices comprising: apair of pressure sensing devices for each pumping station, wherein afirst sensing device of the pair of pressure sensing devices is locatedon one side of the pump in the at least one pipeline segment and asecond sensing device of the pair of pressure sensing devices is locatedon an opposite of the pump in the at least one pipeline segment, whereineach pressure sensing device being capable of sensing one or morepressure waves within the pipeline network, wherein the control unitdetermines the location of the destabilizing in the pipeline networkbased upon the location of the pressure sensing devices that sensed apressure wave.
 41. The system for monitoring a pipeline networkaccording to claim 40, wherein the control unit identifies remedialmeasures to isolate or correct the possible destabilizing event inresponse to the determination that a possible destabilizing eventexists.
 42. The system according to claim 41, wherein the control unitperforms at least one of reporting the remedial measures to an operatorof the pipeline network and automatically executing the remedialmeasures.
 43. The system according to claim 33, wherein the control unitfurther diagnoses a potential cause of the sensed destabilizing event bycomparing the character of the sensed destabilizing event using anexpert based diagnostic subroutine with at least one of priordestabilizing events, the current operating mode of the pipelinenetwork, the current operating conditions in the pipeline network andthe current operating events in the pipeline network.
 44. The system formonitoring a pipeline network according to claim 43, wherein the controlunit identifies remedial measures to isolate or correct the possibledestabilizing event in response to the determination that a possibledestabilizing event exists.
 45. The system according to claim 44,wherein the control unit performs at least one of reporting the remedialmeasures to an operator of the pipeline network and automaticallyexecuting the remedial measures.
 46. A pipeline network for transportingfluids, comprising: a first facility; a second facility; at least onepipeline segment connecting the first facility and the second facilitysuch that the fluid can flow between the first facility and the secondfacility; at least one pumping station connected to the at least onepipeline segment, whereby fluid flowing through the at least onepipeline segment flows through the at least one pumping station; and amonitoring system for monitoring the operation of the pipeline network,wherein the monitoring system comprising: a plurality of pressuresensing devices for sensing the presence of one or more pressure waveswithin the pipeline network; a plurality of remote monitoring devicesoperatively connected to the first facility, the second facility and theat least one pumping station, wherein the remote monitoring devicesmonitor the operation of the pipeline network and collect operating dataof the pipeline network, wherein each of the plurality of pressuresensing devices being operatively connected to at least one remotemonitoring device; and a control unit operatively connected to theplurality of remote monitoring devices for controlling the operation ofthe pipeline network based upon signals received from the plurality ofremote monitoring devices, wherein the control unit detects the presenceof possible destabilizing events in the pipeline network in response tothe sensed pressure waves based upon determining at least one of (i)whether or not detected variations in the sensed pressure waves exceedsan accepted standard deviation, (ii) whether or not a subsequentialdecompression characteristic is present following the detection of thevariation in sensed pressure waves, and (iii) whether or not the sensedpressure waves exceed a predetermined stable operating threshold, wherethe predetermined stable operating threshold is adjusted based upon atleast one of the current operating mode, current operating conditionsand current operating events.
 47. The pipeline network according toclaim 46, wherein the control unit empirically determines the acceptedstandard deviation.
 48. The pipeline network according to claim 46,wherein each of the at least one pumping station includes a pump,wherein the plurality of pressure sensing devices comprising: a pair ofpressure sensing devices for each pumping station, wherein a firstsensing device of the pair of pressure sensing devices is located on oneside of the pump in the at least one pipeline segment and a secondsensing device of the pair of pressure sensing devices is located on anopposite of the pump in the at least one pipeline segment, and whereineach pressure sensing device being capable of sensing one or morepressure waves within the pipeline network.
 49. The pipeline networkaccording to claim 46, wherein the control unit includes a real timeoptimizer, wherein the real time optimizer determines the presence of adestabilizing event in the pipeline network based upon the sensedpressure waves.
 50. The pipeline network according to claim 49, furthercomprising: at least one display operatively connected to the controlunit, wherein the presence of a destabilizing is displayed on the atleast one display
 51. The pipeline network according to claim 49,wherein the control unit determines whether or not variations in thesensed pressure waves are present, wherein the real time optimizerfurther determines whether or not the variation exceeds an acceptedstandard deviation.
 52. The pipeline network according to claim 51,wherein the real time optimizer determines the certainty of the possibledestabilizing event by comparing the determination of a possibledestabilizing event based upon sensed pressure waves with one or moresensed pipeline network operating conditions sensed by the plurality ofremote monitoring devices.
 53. The pipeline network according to claim51, wherein each of the at least one pumping station includes a pump,wherein the plurality of pressure sensing devices comprising: a pair ofpressure sensing devices for each pumping station, wherein a firstsensing device of the pair of pressure sensing devices is located on oneside of the pump in the at least one pipeline segment and a secondsensing device of the pair of pressure sensing devices is located on anopposite of the pump in the at least one pipeline segment, wherein eachpressure sensing device being capable of sensing one or more pressurewaves within the pipeline network, wherein the real time optimizerdetermines the location of a destabilizing event in the pipeline networkbased upon the location of the pressure sensing devices that sensed apressure wave.
 54. The pipeline network according to claim 53, whereinthe control unit identifies remedial measures to isolate or correct thepossible destabilizing event in response to the determination that apossible destabilizing event exists.
 55. The system according to claim54, wherein the control unit performs at least one of reporting theremedial measures to an operator of the pipeline network andautomatically executing the remedial measures.
 56. The pipeline networkaccording to claim 46, wherein the control unit identifies remedialmeasures to isolate the possible destabilizing event in response to thedetermination that a possible destabilizing event exists.
 57. The systemaccording to claim 56, wherein the control unit performs at least one ofreporting the remedial measures to an operator of the pipeline networkand automatically executing the remedial measures.